Small Gas Fields Research Articles

Economic efficiency of synthetic motor fuels from natural gas

In this paper we study alternative ways to meet the demand for motor fuels growing in connection with the inevitable rise in oil prices over the next decade or two. One of these is to use natural gas as a motor fuel and as a raw material for synthetic motor oils. Calculation results of the comparative effectiveness of the gas-to-liquids (GTL) technology of motor fuel production from natural gas are presented. It is shown that these technologies look economically promising in countries, which have their own sources of natural gas, especially in small and remote gas fields.

Membrane separation of nitrogen from natural gas: A case study from membrane synthesis to commercial deployment

Abstract Fourteen percent of U.S. natural gas contains excess nitrogen, and cannot be sent to the national pipeline without treatment. Nitrogen is difficult to economically separate from methane, by any technology. Currently, the only process used on a large scale is cryogenic liquefaction and fractionation, but this technology requires economies of scale to be practical. Many owners of small gas fields cannot produce their gas for lack of suitable nitrogen separation technology. This paper describes the development of selective membranes to treat natural gas containing high concentrations of nitrogen. Membranes selectively permeate either nitrogen or methane, the principal constituent of natural gas. Our work has shown that methane-selective membranes are generally preferable and membranes with high permeances and methane/nitrogen selectivities of approximately 3–3.5 were developed. This selectivity is modest, so commercial systems often require multi-stage or multi-step process designs. Despite the design complexity and compression requirements, multi-step/multi-stage membrane systems are the lowest cost nitrogen removal technology in many applications. To date, 12 membrane-based systems for nitrogen removal for natural gas processing have been installed.

Amendment of the Dutch Mining Act: Fallow Acreage and Gas Storage

Whether we like it or not, Dutch gas reserves are in decline, especially those located on the Dutch part of the Continental Shelf. The remaining fields are getting smaller and it is important to develop them before it is too late. At the same time, the Netherlands is gearing up for a role as major gas hub in Europe, commonly referred to as the Dutch ‘gas roundabout’. The Cabinet has recently submitted a Bill to the Lower House to foster the development of small gas fields and gas storage facilities. The objective is laudable, but certain observations are warranted on the present wording of this Bill.

NGH Chain: Gas-Transportation Concept

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 12807, "NGH Chain: A New Gas Transportation Concept," by T. Kawasaki, K. Bando, and Y. Suehiro, SPE, Japan Oil, Gas, and Metals National Corporation, prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3-5 De cem ber. The paper has not been peer reviewed. In general, long-distance liquefied natural gas (LNG) transportation projects are economically feasible for very large natural-gas reserves volumes. Japan Oil, Gas, and Metals National Corporation and Japanese engineering companies have focused on natural-gas hydrate (NGH) as a gas-transportation concept. It is important to consider optimizing the process and to understand the effect on the chain and optimize the entire NGH chain. Background Many medium and small gas fields within 6000 km of Japan are difficult to develop by conventional techniques, such as LNG and pipelines. NGH may be an economical gas-transportation method. NGH contains 170 times the gas volume compared with liquid or gaseous states. Therefore, initial cost of the NGH process is estimated to be less than that for LNG. LNG transportation is economically feasible for long-distance transportation. Pipelines are suitable for relatively-short-distance transportation because of higher capital cost. NGH transportation is a solution for small-to-medium-scale or remote gas fields, as shown in Fig. 1. Feasibility studies shown in Fig. 2 indicate that NGH transportation has an economic advantage for suitably sized gas reserves and transportation distance. Several systems have been developed to form NGH, including the bubbling/stirring-type formation reactor, the water-spraying-type formation reactor, and a hydrate-formation system that uses microbubbles with a tubular reactor, which obtains a higher formation rate than the other systems. Further improvement is needed in the precision of the feasibility study along with advances in technology. Conceptual Design The purpose of this study was the life cycle carbon dioxide (LCCO2) analysis of natural-gas transportation to Japan as NGH. In the selected model, natural gas is converted to NGH at the production plant and delivered to Japan by an NGH-carrier ship from existing undeveloped natural-gas fields in coastal areas of Southeast Asia. The base case production rate was 1×106 tonnes/a of LNG equivalent with a transport distance of 6000 km. The study presumed that the gas would be used in a power plant. LCCO2 Analysis The scope of investigation includes processes between the production facilities (including inlet-gas treatment) and the regasification facilities.

新たな海洋天然ガス開発技術―ＬＮＧ‐ＦＰＳＯ―

LNG-FPSO (Floating Production Storage and Offloading Unit) is a floating system installed LNG plant on it and enables to export natural gas as LNG from offshore field to gas markets directly. This system may have significant advantages for development of deepwater, remote or small size offshore gas field for the following reasons: · Minimum Environmental Impact · Reduction in CAPEX/OPEX · Potential Reduction of Project Lead Time · Reduction in Abandonment Work & CostINPEX Corporation (INPEX) has conducted several studies on LNG-FPSO to assess the feasibility since 2001. Based on the results, INPEX conducted Pre-FEED (Front End Engineering & Design) for LNG-FPSO for the INPEX's Abadi gas field located in the deepwater remote area in Arafura Sea Offshore Indonesia from September 2007 to July 2008.This presentation outlines the concept of LNG-FPSO for the Abadi gas field and discusses the applicability of LNG-FPSO.

ＮＧＨによる天然ガス輸送技術

Traditionally, natural gas is transported by pipelines or by ships as liquefied natural gas (LNG). Because of large costs of liquefaction plants and carriers for natural gas, LNG transportation system has been applied only to very large gas fields. For meeting the increasing demand and stable supply of natural gas, small and medium size gas fields need to be utilized. To enable the utilization of small and medium size gas fields, it is necessary to develop another transportation system for natural gas, with lower initial costs.Gas hydrate is a crystalline solid which consists of gas molecules each surrounded by a cage of water molecules. Use of gas-hydrates for transportation of natural gas was first proposed by Gudmundsson et al. (Norway) in 1996. The temperature of natural gas hydrate (NGH) through transportation remains higher than that of liquefied natural gas (LNG), and accordingly, transportation of NGH is expectably more flexible in terms of its facilities and equipments. NGH can be a medium for natural gas transportation for comparatively small gas fields to which LNG transportation system is not economically applicable.The development of the NGH transportation system started in year 2001. This paper outlines the system and results of current study.

NGH-FPSO用タンデムオフローディング装置の開発

NGH (Natural Gas Hydrate)-FPSO is deemed as one of the attractive solutions for relatively small gas fields. NGH process plant is installed on board FPSO and it produces NGH from raw gas transferred directly from subsea wells through flowlines and risers. For 3 years since 2004, we have been investigating tandem offloading system for NGH-FPSO and a shuttle tanker in the south east Asia and Oceania. We evaluated workability of the tandem offloading system for NGH-FPSO under combined environmental conditions. As a result, we confirmed that workability under the offloading conditions attained 100% by using a mooring unit that has large restitution force. Based on the aforementioned results, we carried out a safety assessment of the offloading system according to HAZID (Hazard Identification Study) and were awarded AIP (Approval in Principle) by NK. Furthermore, comparison of economical efficiency between NGH-Chain and LNG-Chain, under the conditions that gas production was between 48 to 275MMscfd, the production period was 30 years, and the destination was Japan, indicated that NGH was advantageous when gas production was 80MMscfd or less. The results of investigation on the tandem offloading system for NGH-FPSO are reported in this paper.

Gas hydrate formation in a gas-liquid mixture behind a shock wave

621 In this work, a new shock-wave technique for intensifying the process of hydrate formation of gases in gas‐liquid mixtures is proposed. There exist different methods for increasing the rate of this process, namely, fine dispersion of a jet saturated by a gas in a gas atmosphere [1‐3], intense stirring of water saturated by a gas dissolved in it [2, 4], exposure of a gas-saturated liquid to vibration [5], and exposure of a medium to ultrasound [6]. The main disadvantage of these methods is the low rate of gas hydrate formation and, as a consequence, the low efficiency of setups based on these techniques. In the absence of pipelines, one of the promising methods for transportation of natural gas consists in converting it into the gas hydrate state and then transporting it in a solid state at atmospheric static pressure and a low temperature (‐10 ° C to ‐20 ° C). The estimates made by Japanese and Norwegian scientists show that the gas hydrate technique for transportation and storage of natural gas is most cost-effective for small gas fields and shelf natural gas fields. A possible way of using the method proposed is the crystal hydrate method for demineralization of mineralized water. Using freon hydrates for this purpose is simplest from the engineering standpoint and most cost-effective [7]. In [8‐10] and some other books, the properties of gas hydrates and the main conditions and features of their formation are described and the mechanisms of gas hydrate formation and the types of their crystallization are presented. Much attention is given to physical and chemical methods for studying both man-made and natural gas hydrates. In this study, we experimentally investigate the process of gas bubble fragmentation and dissolution with the formation of freon-12 hydrate behind a shock wave of a moderate amplitude in water with gas bubbles. We carry out a theoretical analysis of the process of hydrate formation behind a steplike shock front and compare the results to the experimental data. The experiments were conducted in a shock tube. The test section was a 1.5 m-long vertical thick-walled steel tube with an inner diameter of 53 mm, which was limited from below by a rigid wall. The test section was filled with water containing freon-12 bubbles and was thermostatically controlled. The bubble dimensions were determined by capturing them with a digital camera equipped with additional optics through optical windows made in the upper part of the test section with a required time lag behind the shock front. The steplike pressure waves were generated by the breakdown of a diaphragm separating a 2 m-long high-pressure chamber and the test section. The pressure wave profiles were recorded by pressure transducers located along the test section and mounted flush with its inner wall. The local profile of the variation of the gas content (by volume) behind the shock wave was measured by a conductivity transducer placed at the middle part of the test section. Signals from the transducers were applied to an analog-to-digital converter and were then com

Seismic hazard due to small-magnitude, shallow-source, induced earthquakes in The Netherlands

The Netherlands has large on-land gas reservoirs, which are being exploited since 1960. Small-magnitude ( M L ≤ 3.5), shallow (depth < 4 km) events induced by this gas exploitation cause light damage and much concern to the regional population. As one of the consequences the Dutch law requires since 2003 seismic hazard and risk estimates for each mining concession. Up to now only general quantitative hazard estimates, maximum possible earthquake and maximum possible intensity were available. Here we provide more specific quantitative hazard estimates. A long-term monitoring program shows a stationary rate of seismicity since 1992, probably coupled to a stationary production rate. Based on this we present a first order site-specific hazard estimate using a Probablistic Seismic Hazard Analysis (PSHA). We predict, and observe, relatively high Peak Ground Accelerations (PGA). PGA above 0.2 g is not unusual, but damage has so far been restricted to non-structural damage, mainly cracks in masonry. Relevant hazard estimates for the local, mostly low-rise buildings are given in terms of Peak Ground Velocity (PGV) or the maximum in the 50% damped response spectra at 10 Hz. For example, above the largest Dutch gas field, the Groningen field, we expect that peak values of 20 and 30 mm/s may be exceeded with a 10% probability in 1 and 10 years, respectively. Above some small (about 3–4 km 2) gas fields, Roswinkel and Bergermeer, we expect values around 35 and 60 mm/s, respectively. These values, which exceed the Dutch building research (SBR) vibration guidelines, are obtained using simple model assumptions and are accompanied by an uncertainty analysis. The PSHA provides an important additional insight for the decision maker as to which relevant uncertainties may be decreased and which not. This information can be and is being used to set research and monitoring priorities.

Q&amp;A with Maroot Mrigadat

Maroot Mrigadat has been President of PTT Exploration and Production plc (PTTEP), Thailand’s leading petroleum exploration and production company, since October 2003. His major responsibilities include managing the exploration, development, and production activities of 23 oil and gas assets in seven countries, overseeing the company’s 1,000 employees, and implementing PTTEP’s corporate strategic goals and investment strategy. He also oversees the management of PTTEP’s two non-E&amp;P investment projects. Mrigadat started his career in 1979 with the Petroleum Authority of Thailand, now PTT plc, as an engineer in the company’s E&amp;P department. In 1984, he became Director of its Drilling and Production Div. and in 1988 became Assistant President, Management, responsible for human resources, procurement, finance, accounting and budget, and corporate policies. He joined PTTEP in 1989 as Vice President, Production, in charge of reservoir engineering, drilling, facility, and construction, and was later promoted to Vice President, Operations, a post he held from 1994 to 1997. In 1997, Mrigadat became General Manager Designated, Bongkot Project, and was later named Vice President, Bongkot Project, responsible for the operatorship transfer from Total to PTTEP. In 1999, he was appointed Senior Vice President, Operations, in charge of the Bongkot, Arthit, and PTTEP 1 projects. During 2002 and 2003, he was Senior Vice President, Business Development, in charge of formulating investment strategy for company growth in southeast Asia and internationally. Mrigadat is Chairman and Director of 11 PTTEP subsidiaries. His other positions include Director of Thai Oil Power Co., Director of Carigali-PTTEPI Operating Co. Sdn. Bhd., Director of Moattama Gas Transportation Co., Director of Energy Complex Co. Ltd., and Council of Trustee Member of the Petroleum Inst. of Thailand. Mrigadat earned BS and MS degrees in petroleum engineering from the U. of Texas at Austin. What is your company’s current domestic and international oil and gas production? PTTEP’s domestic production this year is approximately 132,000 BOE/D. Gas and condensate from the Gulf of Thailand and small onshore fields constitute 82% of this daily production. Internationally, we hold equity in several producing offshore gas assets in Myanmar. This adds an additional 37,000 BOE/D of production to our portfolio. We are also developing a small gas and condensate field onshore Oman, and production should be on stream next year. Although production will be small initially, we are hopeful that it will increase significantly in the near future. Equally important is that the Oman development represents a key milestone in our company’s expansion into the Middle East region. What are PTTEP’s oil and gas production goals? Our goal is quite simple. We want to quadruple our production by the year 2020. We also want to increase oil production to the pro-portion of gas in our portfolio. Currently, gas accounts for a large percentage of our portfolio. What are PTTEP’s most attractive upstream areas? In terms of current holdings, the Gulf of Thailand and the Gulf of Mottaban in Myanmar are very attractive. We see good prospects in Oman not just upstream but midstream as well. In terms of future growth, our focus is not so different from many oil companies. The Middle East continues to attract interest. Africa holds promise, particularly with recent major discoveries offshore. We also believe that Indonesia holds tremendous potential.

Gas reserves and reservoir trends in The Netherlands

The Netherlands is one of the largest gas producers in Europe with about 71.2 Bcm (2.51 Tcf) of gas produced during the year 2002, half of which is exported, supplying Europe with about 20% of its total consumption. Significant gas production in The Netherlands started in 1965, reached a peak during 1976 with 101 Bcm (3 Tcf) and by year end 2002, a total of 2622 Bcm (92.6 Tcf) had been extracted. Currently the government limits yearly gas production to 80 Bcm, although the rate in the past four years has been well under this limit. Early exploration was started before the Second World War by a precursor of NAM (the 50/50 Shell-Exxon joint venture active in The Netherlands) and in 1943 the Schoonebeek oil field was found followed by Coevorden gas field in 1951. In 1959, the giant Groningen gas field was discovered by NAM, changing the face of exploration in The Netherlands. Since that time NAM has retained its dominant position as operator controlling about three quarters of annual gas production and reserves. Public domain access of data on gas and oil fields in The Netherlands is scarce, with pre-2003 legislation allowing operators to hold tight all information on onshore wells. Since most onshore concessions are large, held over long periods of time (several in perpetuity), and have no relinquishment obligations, many fields have been found and are in production without any data entering the public arena. Offshore, pre-2003 legislation required operators to release well data after 10 years. Offshore concessions are relatively large and many contain several producing fields for which no or little data is in the public domain. Following the new legislation in force since 1 January 2003 detailed production data and all on- and offshore wells and seismic data older than 5 years have to be released. However, reserve figures of fields are not in the public domain. Reserve data submitted by the operators remain confidential for a period of 10 years and in the absence of any legal requirement operators use this advantage. On a yearly basis, the government publishes general estimates on reserves, but not for individual fields. Data on the current reserve distribution for fields, reservoir trends and for licence holders are not easily ascertained. This paper attempts to fill this information gap by reviewing reserves whether these are in developed or undeveloped fields. Reserves are oil or gas volumes that can be commercially recovered at current economic conditions, industry practices and government regulations. Developed reserves are those being produced today while undeveloped fields are not yet on stream. Remaining reserves are those left in a producing field. Initial (or ultimate) reserves of a field are the cumulative production plus the remaining reserves. Because the technical data of the fields are not available, the different reserves categories are used here informally and without strict definitions. In this paper a difference has been made between the giant Groningen gas field and the other fields that are collectively called the ‘Small fields’. This term is used in a comparative sense with the Groningen field as the measuring stick, and is applied due to the Small Field Policy in The Netherlands, which allows operators priority to bring small gas fields immediately on stream in lieu of production from the Groningen field. Exploration for and production from small fields is therefore not constrained by demand for gas. Moreover because the Groningen field acts as a swing producer, small fields can produce with high load factors. The Small Field Policy sets production constraints on the Groningen field. In addition the gas price is kept relatively high because it is linked to a basket of oil product prices. Without these production constraints and the linkage of the gas price to that for oil, the low production costs and high production capacity of the Groningen field would result in low gas prices for Western Europe and most small fields in The Netherlands and surrounding countries would have been uneconomic during much of the lifetime of the Groningen field.

発展途上国の未開発天然ガス資源を利用する都市ガス事業導入スキームの一考察

Natural gas is regarded as an environmentally friendly energy and one of the cleanest forms of fossil fuel energy. Therefore. the development and promotion of natural gas has been very active around the world. Although natural gas reserves are widely distributed all over the world, most of these reserves are located in undeveloped areas, far away from consuming cities. A lot of investment will be necessary such as pipeline construction, liquefaction facilities and storage tanks, to bring these reserves to market. Only large scale gas fields have been tapped so far, because they are relatively easy to commercialize, but small or middle scale gas fields have been left undeveloped, due to the economy of scale difficulties.This paper discusses the possibility of natural gas utilization among the Asian-region developing countries, which own undeveloped small or middle scale gas fields.

The Hatfield Moors and Hatfield West Gas (Storage) Fields, South Yorkshire

abstract Hatfield Moors and Hatfield West are two small gas fields with GIIP of 6.1 BCF and 2.4 BCF, respectively on adjacent licences PL161-3 and PL 162-2, east of Doncaster in South Yorkshire, England, operated and wholly owned by Edinburgh Oil &amp; Gas pic. This paper describes the accidental discovery of the Hatfield Moors Gas Field and its subsequent development and eventual utilization for gas storage, the first such project onshore UK. The nearby Hatfield West Field is also described. The two fields are located on adjacent faulted anticlinal structures in the NW part of the Gainsborough half-graben. The reservoir for both fields is the Westphalian B Oaks Rock sandstone. Reservoir quality is excellent. A gas storage project was agreed with Scottish Power in 1998. Two horizontal wells, Hatfield Moors-5 (1998) and Hatfield Moors-5z (1999) have been drilled for the project by Edinburgh Oil &amp; Gas pic using innovative drilling techniques. Since 1999 gas has been imported from the Transco network and exported from the reservoir according to market demands under the terms of the gas storage contract.

The Sean North, Sean South and Sean East Fields, Block 49/25a, UK North Sea

Abstract Sean North, Sean South and Sean East are small prolific gas fields located on the Indefatigable Shelf in the Southern North Sea. They, like most of the other fields in the area, have a Carboniferous source, a Rotliegend aeolian sandstone reservoir and a Zechstein evaporite cap rock. Sean North and South have been developed to fulfil a peak-shaving role, being produced for only a few days per year in times of high gas demand when they can produce at rates of up to 600 MMSCF/D. East Sean is sold to the direct market. Reserves for the fields are 234 BCF (North), 488 BCF (South) and 127 BCF (East).

Large-scale flow of geofluids at the Dead Sea Rift

Buoyancy-driven flow associated with salinity variations is proposed as the principal driving force that has caused large-scale migration of brine and hydrocarbons at the Dead Sea Rift. Numerical simulations indicate the coexistence of two basin-scale groundwater flow systems, one atop the other, with opposite flow directions. The first is a density-driven migration of brine through deep aquifers from the rift outward, which has affected hydrocarbon maturation and migration, and the formation of three small gas fields. The second is a topography-driven groundwater flow through relatively shallow aquifers from the surrounding highlands toward the rift valley, which has caused oil biodegradation, forming heavy oils and asphalts. Simulations indicate that flow-field configurations of both groundwater and hydrocarbons have changed during the structural evolution of the rift, illustrating the interrelationships between basin formation, paleohydrology and hydrocarbon reservoir formation.

The Miocene petroleum system of the Sava Depression, Croatia

The Sava Depression, located on the southern margin of the Pannonian Basin, contains a number of small oil and gas fields. The depression is filled principally with Neogene sediments resting on Palaeozoic crystalline basement. Rifting occurred in Early to Middle Miocene times. Geochemical data imply that Middle to Upper Miocene pelites are good oil-prone source rocks. Most of the oil and oil–gas fields are situated at depths of 370 to 2300 m. Weathered basement rocks and Miocene conglomerates and sandstones are reservoir rocks and the fields are mostly structural and/or structural–stratigraphic traps. Oils from the fields correlate well with the identified source rock facies and maturity level and we propose short migration distances. Sava oil properties show variations in bulk and specific parameters that can be attributed to post-generative processes.

Palaeohydrology of hydrocarbon maturation, migration and accumulation in the Dead Sea Rift

It is proposed that hydrocarbon maturation, migration and accumulation in the Dead Sea rift, which took place during the last 3‐6 Myr, were significantly affected by density-driven groundwater flow, from the rift westwards through deep aquifers. To test this hypothesis, a quantitative feasibility study was carried out using numerical modelling, which assesses the effects of structural evolution, groundwater flow, heat transport and salinity redistribution on hydrocarbon migration. Results indicate that a significant fraction of hydrocarbons have escaped to the land surface within the graben. Oil that has been forced westward into the rift flanks with the migrating brine is still moving. However, gas that has been forced westward has been trapped and forms the three small commercial gas fields: Zohar, Kidod and Haqanaim. A significant portion of the oil has biodegraded forming heavy oils and asphalts due to subsequent flushing by meteoric water. Simulations indicate that flow-field configurations of both groundwater and hydrocarbons have changed during the structural evolution of the rift, illustrating the interrelationships between basin formation, palaeohydrology and hydrocarbon reservoir formation.

アジア太平洋地域の中小規模ガス田とＦＰＳＯ開発の状況

There is going to be considerable growth in natural gas demand in Japan.Because natural gas has an environmental advantage in comparison with other resources such as petroleum and coal, the recoverable reserves of natural gas is equal to those resources. The Japanese gas market occupies a small share in terms of total primary energy consumption. It is only about 12%, nearly half the OECD average.In the Asia-Pacific region, a number of small offshore gas fields have not yet been developed. The reasons for this are lack of commercially attractive development solutions, lack of nearby markets and lack of commercial incentives, so that these fields can not compete with the development of larger gas fields.Therefore, Japan National Oil Corporation is coducting studies and research for the development of marginal offshore gas fields. The first, survey of small gas fields in the region, including reserves water depth, distance to market etc., began in 1997FY and will continue until 1998FY. Technical solutions for small gas fields will include potential utilization of LNG-FPSO (floating production, storage and offloading) and conversion of GTL (gas to liquid). For exploitation of small offshore gas fields, LNG-FPSO system has emerged as a potentially feasible approach. The first part of this paper presents the interim results of the outline of small gas fields in the Asia-Pacific region.The second part of this paper presents the results of the following studies of LNG-FPSO in the region, (1) design conditions and areas of specific investigations, (2) outline of the LNG-FPSO concept, (3) safty assessment studies on offloading systems, (4) model testing for evaluation of the limiting weather conditions, and (5) economic studies. The concepts of LNG-FPSO are considered to be economically and technically feasible, although certain technical adjustments need to be incorporated to reflect actual field conditions.

天然ガス利用技術と環境との調和

In Japan, the greater part of imported natural gas is consumed in the power industry and the gas industry. For efficiently utilizing the energy generated from natural gas combustion, new systems based on repowering or co-generation, such as combined cycle power generation, gas co-generation, gas air conditioning, power generation by refuse incineration, have been developed in these industries.Recently it has become very important to develop abundant small gas fields and to recover flared natural gas. The technologies, by which natural gas is chemically converted to liquid materials, such as methanol, dimethyl ether and GTL, are being watched with keen interest because these liquids are easier to transport than natural gas.In future, it will be expected to develop new technologies for converting natural gas to useful raw materials in chemical industries.

Progressive Production Technology in Complicated Dispersed Small Oil and Gas Fields

Abstract Producing experience in complicated, dispersed small oil and gas fields in the west peripheral area of Daqing oilfield has led to development of a system of progressive production technology. Experience shows that this technology system is feasible and of good practical value to the production of a complicated small oilfield.